The present invention relates to down-hole drilling, and especially to the optimization of drill bit parameters.
BACKGROUND: ROTARY DRILLING
Oil wells and gas wells are drilled by a process of rotary drilling, using a drill rig such as is shown in FIG. 10. In conventional vertical drilling, a drill bit 10 is mounted on the end of a drill string 12 (drill pipe plus drill collars), which may be miles long, while at the surface a rotary drive (not shown) turns the drill string, including the bit at the bottom of the hole.
Two main types of drill bits are in use, one being the roller cone bit, an example of which is seen in FIG. 11. In this bit a set of cones 16 (two are visible) having teeth or cutting inserts 18 are arranged on rugged bearings on the arms of the bit. As the drill string is rotated, the cones will roll on the bottom of the hole, and the teeth or cutting inserts will crush the formation beneath them. (The broken fragments of rock are swept uphole by the flow of drilling fluid.) The second type of drill bit is a drag bit, having no moving parts, seen in FIG. 12.
There are various types of roller cone bits: insert-type bits, which are normally used for drilling harder formations, will have teeth of tungsten carbide or some other hard material mounted on their cones. As the drill string rotates, and the cones roll along the bottom of the hole, the individual hard teeth will induce compressive failure in the formation. The bit's teeth must crush or cut rock, with the necessary forces supplied by the “weight on bit” (WOB) which presses the bit down into the rock, and by the torque applied at the rotary drive.
BACKGROUND: DRILL STRING OSCILLATION
The individual elements of a drill string appear heavy and rigid. However, in the complete drill string (which can be more than a mile long), the individual elements are quite flexible enough to allow oscillation at frequencies near the rotary speed. In fact, many different modes of oscillation are possible. (A simple demonstration of modes of oscillation can be done by twirling a piece of rope or chain: the rope can be twirled in a flat slow circle, or, at faster speeds, so that it appears to cross itself one or more times.) The drill string is actually a much more complex system than a hanging rope, and can oscillate in many different ways; see WAVE PROPAGATION IN PETROLEUM ENGINEERING, Wilson C. Chin, (1994).
The oscillations are damped somewhat by the drilling mud, or by friction where the drill pipe rubs against the walls, or by the energy absorbed in fracturing the formation: but often these sources of damping are not enough to prevent oscillation. Since these oscillations occur down in the wellbore, they can be hard to detect, but they are generally undesirable. Drill string oscillations change the instantaneous force on the bit, and that means that the bit will not operate as designed. For example, the bit may drill oversize, or off-center, or may wear out much sooner than expected. Oscillations are hard to predict, since different mechanical forces can combine to produce “coupled modes”; the problems of gyration and whirl are an example of this.
BACKGROUND: OPTIMAL DRILLING WITH VARIOUS FORMATION TYPES
There are many factors that determine the drillability of a formation. These include, for example, compressive strength, hardness and/or abrasiveness, elasticity, mineral content (stickiness), permeability, porosity, fluid content and interstitial pressure, and state of underground stress.
Soft formations were originally drilled with “fish-tail” drag bits, which sheared the formation. Fish-tail bits are obsolete, but shear failure is still very useful in drilling soft formations. Roller cone bits designed for drilling soft formations are designed to maximize the gouging and scraping action, in order to exploit both shear and compressive failure. To accomplish this, cones are offset to induce the largest allowable deviation from rolling on their true centers. Journal angles are small and cone-profile angles will have relatively large variations. Teeth are long, sharp, and widely-spaced to allow for the greatest possible penetration. Drilling in soft formations is characterized by low weight and high rotary speeds.
Hard formations are drilled by applying high weights on the drill bits and crushing the formation in compressive failure. The rock will fail when the applied load exceeds the strength of the rock. Roller cone bits designed for drilling hard formations are designed to roll as close as possible to a true roll, with little gouging or scrapping action. Offset will be zero and journal angles will be higher. Teeth are short and closely spaced to prevent breakage under the high loads. Drilling in hard formations is characterized by high weight and low rotary speeds.
Medium formations are drilled by combining the features of soft and hard formation bits. The rock is failed by combining compressive forces with limited shearing and gouging action that is achieved by designing drill bits with a moderate amount of offset. Tooth length is designed for medium extensions as well. Drilling in medium formations is most often done with weights and rotary speeds between that of the hard and soft formations.
BACKGROUND: ROLLER CONE BIT DESIGN
The “cones” in a roller cone bit need not be perfectly conical (nor perfectly frustroconical), but often have a slightly swollen axial profile. Moreover, the axes of the cones do not have to intersect the centerline of the borehole. (The angular difference is referred to as the “offset” angle.) Another variable is the angle by which the centerline of the bearings intersects the horizontal plane of the bottom of the hole, and this angle is known as the journal angle. Thus as the drill bit is rotated, the cones typically do not roll true, and a certain amount of gouging and scraping takes place. The gouging and scraping action is complex in nature, and varies in magnitude and direction depending on a number of variables.
Conventional roller cone bits can be divided into two broad categories: Insert bits and steel-tooth bits. Steel tooth bits are utilized most frequently in softer formation drilling, whereas insert bits are utilized most frequently in medium and hard formation drilling.
Steel-tooth bits have steel teeth formed integral to the cone. (A hard facing is typically applied to the surface of the teeth to improve the wear resistance of the structure.) Insert bits have very hard inserts (e.g. specially selected grades of tungsten carbide) pressed into holes drilled into the cone surfaces. The inserts extend outwardly beyond the surface of the cones to form the “teeth” that comprise the cutting structures of the drill bit.
The design of the component elements in a rock bit are interrelated (together with the size limitations imposed by the overall diameter of the bit), and some of the design parameters are driven by the intended use of the product. For example, cone angle and offset can be modified to increase or decrease the amount of bottom hole scraping. Many other design parameters are limited in that an increase in one parameter may necessarily result in a decrease of another. For example, increases in tooth length may cause interference with the adjacent cones.
BACKGROUND: TOOTH DESIGN
The teeth of steel tooth bits are predominantly of the inverted “V” shape. The included angle (i.e. the sharpness of the tip) and the length of the tooth will vary with the design of the bit. In bits designed for harder formations the teeth will be shorter and the included angle will be greater. Gage row teeth (i.e. the teeth in the outermost row of the cone, next to the outer diameter of the borehole) may have a “T” shaped crest for additional wear resistance.
The most common shapes of inserts are spherical, conical, and chisel. Spherical inserts have a very small protrusion and are used for drilling the hardest formations. Conical inserts have a greater protrusion and a natural resistance to breakage, and are often used for drilling medium hard formations.
Chisel shaped inserts have opposing flats and a broad elongated crest, resembling the teeth of a steel tooth bit. Chisel shaped inserts are used for drilling soft to medium formations. The elongated crest of the chisel insert is normally oriented in alignment with the axis of cone rotation. Thus, unlike spherical and conical inserts, the chisel insert may be directionally oriented about its center axis. (This is true of any tooth which is not axially symmetric.) The axial angle of orientation is measured from the plane intersecting the center of the cone and the center of the tooth.
BACKGROUND: BOTTOM HOLE ANALYSIS
The economics of drilling a well are strongly reliant on rate of penetration. Since the design of the cutting structure of a drill bit controls the bit's ability to achieve a high rate of penetration, cutting structure design plays a significant role in the overall economics of drilling a well.
It has long been desirable to predict the development of bottom hole patterns on the basis of the controllable geometric parameters used in drill bit design, and complex mathematical models can simulate bottom hole patterns to a limited extent. To accomplish this it is necessary to understand first, the relationship between the tooth and the rock, and second, the relationship between the design of the drill bit and the movement of the tooth in relation to the rock. It is also known that these mechanisms are interdependent.
To better understand these relationships, much work has been done to determine the amount of rock removed by a single tooth of a drill bit. As can be seen by the forgoing discussion, this is a complex problem. For many years it has been known that rock failure is complex, and results from the many stresses arising from the combined movements and actions of the tooth of a rock bit. (Sikarskie, et al, PENETRATION PROBLEMS IN ROCK MECHANICS, ASME Rock Mechanics Symposium, 1973). Subsequently, work was been done to develop quantitative relationships between bit design and tooth-formation interaction. This has been accomplished by calculating the vertical, radial and tangential movement of the teeth relative to the hole bottom, to accurately represent the gouging and scrapping action of the teeth on roller cone bits. (Ma, A NEW WAY TO CHARACTERIZE THE GOUGING-SCRAPPING ACTION OF ROLLER CONE BITS, Society of Petroleum Engineers No. 19448, 1989). More recently, computer programs have been developed which predict and simulate the bottom hole patterns developed by roller cone bits by combining the complex movement of the teeth with a model of formation failure. (Ma, THE COMPUTER SIMULATION OF THE INTERACTION BETWEEN THE ROLLER BIT AND ROCK, Society of Petroleum Engineers No. 29922, 1995). Such formation failure models include a ductile model for removing the formation occupied by the tooth during its movement across the bottom of the hole, and a fragile breakage model to represent the surrounding breakage.
Currently, roller cone bit designs remain the result of generations of modifications made to original designs. The modifications are based on years of experience in evaluating bit run records and dull bit conditions. Since drill bits are run under harsh conditions, far from view, and to destruction, it is often very difficult to determine the cause of the failure of a bit. Roller cone bits are often disassembled in manufacturers' laboratories, but most often this process is in response to a customer's complaint regarding the product, when a verification of the materials is required. Engineers will visit the lab and attempt to perform a forensic analysis of the remains of a rock bit, but with few exceptions there is generally little evidence to support their conclusions as to which component failed first and why. Since rock bits are run on different drilling rigs, in different formations, under different operating conditions, it is extremely difficult draw conclusion from the dull conditions of the bits. As a result, evaluating dull bit conditions, their cause, and determining design solutions is a very subjective process. What is known is that when the cutting structure or bearing system of a drill bit fails prematurely, it can have a serious detrimental effect of the economics of drilling.
Though numerical methods are now available to model the bottom hole pattern produced by a roller cone bit, there is no suggestion as to how this should be used to improve the design of the bits other than to predict the presence of obvious problems such as tracking. For example, the best solution available for dealing with the problems of lateral vibration, is a recommendation that roller cone bits should be run at low to moderate rotary speeds when drilling medium to hard formations to control bit vibrations and prolong life, and to use downhole vibration sensors. (Dykstra, et al, EXPERIMENTAL EVALUATIONS OF DRILL STRING DYNAMICS, Amoco Report Number F94-P-80, 1994).
Force-Balanced Roller-Cone Bits, Systems, Drilling Methods, and Design Methods
The present application describes improved methods for designing roller cone bits, as well as improved drilling methods, and drilling systems. The present application teaches that roller cone bit designs should have equal mechanical downforce on each of the cones. This is not trivial: without special design consideration, the weight on bit will NOT automatically be equalized among the cones.
Roller-cone bits are normally NOT balanced, for several reasons:
Asymmetric cutting structures. Usually the rows on cones are intermeshed in order to cover fully the hole bottom and have a self-clearance effects. Therefore, even the cone shapes may be the same for all three cones, the teeth row distributions on cones are different from cone to cone. The number of teeth on cones are usually different. Therefore, the cone having more row and more teeth than other two cones may remove more rock and as a results, may spent more energy (Energy Imbalance). An energy imbalance usually leads to bit force imbalance.
Offset effects. Because of the offset, a scraping motion will be induced. This scraping motion is different from teeth row to teeth row and as a result, the scraping force (tangent force) acting on teeth is different from row to row. This will generate an imbalance force on bit.
Tracking effects. If at least one of the cones is in tracking, then this cone will gear with the hole bottom without penetration, the rock not removed by this cone will be partly removed by other two cones. As a result, the bit is unbalanced.
The applicant has discovered, and has experimentally verified, that equalization of downforce per cone is a very important (and greatly underestimated) factor in roller cone performance. Equalized downforce is believed to be a significant factor in reducing gyration, and has been demonstrated to provide substantial improvement in drilling efficiency. The present application describes bit design procedures which provide optimization of downforce balancing as well as other parameters.
A roller-cone bit will always be a strong source of vibration, due to the sequential impacts of the bit teeth and the inhomogeneities of the formation. However, many results of this vibration are undesirable. It is believed that the improved performance of balanced-downforce cones is partly due to reduced vibration.
Any force imbalance at the cones corresponds to a bending torque, applied to the bottom of the drill string, which rotates with the drill string. This rotating bending moment is a driving force, at the rotary frequency, which has the potential to couple to oscillations of the drill string. Moreover, this rotating bending moment may be a factor in biasing the drill string into a regime where vibration and instabilities are less heavily damped. It is believed that the improved performance of balanced-downforce cones may also be partly due to reduced oscillation of the drill string.
The disclosed innovations, in various embodiments, provide one or more of at least the following advantages:                The roller cone bit is force balanced such that axial loading between the arms is substantially equal.        The roller cone bit is energy balanced such that each of the cutting structures drill substantially equal volumes of formation.        The drill bit has decreased axial and lateral operating vibration.        The cutting structures, bearings, and seals have increased lifetime and improved performance and durability.        Drill string life is extended.        The roller cone bit has minimized tracking of cutting structures, giving improved performance and extending cutting structure life.        The roller cone bit has an optimized number of teeth in a given formation area.        Bit performance is improved.        Off-center rotation is minimized.        The roller cone bit has optimized (minimized and equalized) uncut formation ring width.        Energy balanced roller cone bits can be further optimized by minimizing cone and bit tracking.        Energy balanced roller cone bits can be further optimized by minimizing and equalizing uncut formation rings.        Designer can evaluate the force balance and energy balance conditions of existing bit designs.        Designer can design force balanced drill bits with predictable bottom hole patterns without relying on lab tests followed by design modifications.        Designer can optimize the design of roller cone drill bits within designer-chosen constraints.        
Other advantages of the various disclosed inventions will become apparent from the following descriptions, taken in connection with the accompanying drawings, wherein, by way of illustration and example, a sample embodiment is disclosed.
U.S. patent application Ser. No. 09/387,304, filed 31 Aug. 1999, entitled “Roller-Cone Bits, Systems, Drilling Methods, and Design Methods with Optimization of Tooth Orientation”, now U.S. Pat. No. 6,095,262 and claiming priority from U.S. Provisional Application No. 60/098,442 filed 31 Aug. 1998, describes roller cone drill bit design methods and optimizations which can be used separately from or in synergistic combination with the methods disclosed in the present application. That application, which has common ownership, inventorship, and effective filing date with the present application, and its provisional priority application, are both hereby incorporated by reference.